EX-99.1 2 a09042019valarisatbarcla.htm EXHIBIT 99.1
Barclays CEO Energy- Power Conference September 2019

Forward-Looking Statements Statements contained in this investor presentation that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include words or phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “could,” “may,” “might,” “should,” “will” and similar words and specifically include statements involving expected financial performance, effective tax rate, expected expense savings, day rates and backlog, estimated rig availability; rig commitments and contracts; contract duration, status, terms and other contract commitments; estimated capital expenditures; letters of intent or letters of award; scheduled delivery dates for rigs; the timing of delivery, mobilization, contract commencement, relocation or other movement of rigs; our intent to sell or scrap rigs; and general market, business and industry conditions, trends and outlook. In addition, statements included in this investor presentation regarding the anticipated benefits, opportunities, synergies and effects of the merger between Ensco and Rowan are forward-looking statements. Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including actions by rating agencies or other third parties; actions by our security holders; costs and difficulties related to the integration of Ensco and Rowan and the related impact on our financial results and performance; our ability to repay debt and the timing thereof; availability and terms of any financing; commodity price fluctuations, customer demand, new rig supply, downtime and other risks associated with offshore rig operations, relocations, severe weather or hurricanes; changes in worldwide rig supply and demand, competition and technology; future levels of offshore drilling activity; governmental action, civil unrest and political and economic uncertainties; terrorism, piracy and military action; risks inherent to shipyard rig construction, repair, maintenance or enhancement; possible cancellation, suspension or termination of drilling contracts as a result of mechanical difficulties, performance, customer finances, the decline or the perceived risk of a further decline in oil and/or natural gas prices, or other reasons, including terminations for convenience (without cause); the cancellation of letters of intent or letters of award or any failure to execute definitive contracts following announcements of letters of intent, letters of award or other expected work commitments; the outcome of litigation, legal proceedings, investigations or other claims or contract disputes; governmental regulatory, legislative and permitting requirements affecting drilling operations; our ability to attract and retain skilled personnel on commercially reasonable terms; environmental or other liabilities, risks or losses; debt restrictions that may limit our liquidity and flexibility; tax matters including our effective tax rate; and cybersecurity risks and threats. In addition to the numerous factors described above, you should also carefully read and consider “Item 1A. Risk Factors” in Part I and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II of our most recent annual report on Form 10-K, as updated in our subsequent quarterly reports on Form 10-Q, which are available on the SEC’s website at www.sec.gov or on the Investors section of our website at www.valaris.com. Each forward-looking statement speaks only as of the date of the particular statement, and we undertake no obligation to publicly update or revise any forward-looking statements, except as required by law. 2

Outline 1. Company Highlights 2. Market Dynamics 3. Valaris Fleet 4. ARO Drilling 5. Financial Management 6. Integration, Synergies & Operational Highlights 3

Valaris Overview (NYSE: VAL) Fleet Financial Operational • Largest and amongst the highest-quality offshore drilling fleets in the world 16 drillships $ 12 semisubmersibles • $2.7 billion of liquidity • Presence in nearly all major 54 jackups ‒ $0.4 billion of cash and short- offshore markets and on six term investments1 continents • ~$11 billion of gross asset ‒ $2.3 billion unsecured value from rig fleet revolving credit facility2 • Large & diverse customer according to third party base including major, • $2.4 billion of contracted estimates national and independent revenue backlog3 E&P companies • ARO Drilling 50/50 joint • $1.1 billion of debt • Strong track record of venture with Saudi Aramco, maturities prior to 20241 the largest jackup customer safety, innovation and – Ability to add guaranteed worldwide operational excellence and/or secured debt to capital structure 1As of June 30, 2019 pro forma for debt tender offers completed in July that reduced cash and equivalents by $741M 2Borrowing capacity under revolving credit facility is approximately $2.3B through September 2019 and approximately $1.6B from October 2019 4 through September 2022. As of August 1, 2019, the Company had drawn $125M on its revolver to partially fund repayment of the 2019 senior note maturity. 3As of most recent 10-Q filing

Valaris is Focused on Four Key Priorities in 2019 Fleet Strategy & Contracting Assets Driving Value at ARO Drilling Proactive Financial Management Delivering on Integration & Synergy Capture and Operational Excellence 5

Market Dynamics 6

Offshore Project Approvals Expected to Lead to Higher Levels of Capital Expenditures Number of New Major Offshore Project Approvals • With lower project costs 91 88 relative to prior years and 81 74 increasing cash flows from 58 higher commodity prices, the 50 42 40 number of final investment decision approvals for large offshore projects has increased recently 2012 2013 2014 2015 2016 2017 2018 2019E ‒ Drilling rigs required between approval and first production, which averages ~4 years for E&P Offshore Capital Expenditures deepwater projects and ~1.5 328 years for shallow-water projects, 7% and for periodic maintenance CAGR 206 over the life of an offshore well 147 • As a result, capital expenditures are expected to increase at a gradual rate 2014 2015 2016 2017 2018 2019E 2020E 2021E 2022E 2023E over the next several years, Shallow Water Deepwater with the majority of this growth coming from projects Source: Rystad Energy ServiceDemandCube as of July 2019, major projects in deepwater 7 defined as projects with >$250 million of associated capital expenditures

The Global Floater Market is Recovering Total Utilization1 90% • Utilization for the global 80% floater fleet has gradually 70% increased since early 2017 60% due to a higher number of 50% rig years awarded for new 40% contracts, leading to slight 2013 2014 2015 2016 2017 2018 2019 improvement in average spot day rates New Contracts2 150 20 • With contract durations remaining relatively flat 100 15 during this time period, the increase in rig years is 50 10 driven by an increasing number of new contracts 0 5 2013 2014 2015 2016 2017 2018 2019A3 Rig Years (L Axis) Average Contract Duration (R Axis, Months) Source: IHS Markit RigPoint as of August 2019 1Total utilization reflects rigs currently under contract and contracted for future work as a percentage of the global floater fleet; includes benign & harsh-environment rigs; average spot day rates include new mutual contracts signed in a given year 8 2Fixtures data includes new mutual contracts only 3Year-to-date 2019 annualized

The Global Jackup Market is Recovering Total Utilization1 90% • Utilization for the global 80% jackup fleet has also moved 70% higher since early 2017, as 60% a steady increase in rig 50% years awarded for new 40% contracts has led to a 2013 2014 2015 2016 2017 2018 2019 modest improvement in average spot day rates New Contracts2 20 400 • In contrast to floaters, 18 average contract durations 320 16 for jackups have increased 240 14 meaningfully in 2019, 160 contributing to the increase 80 12 in rig years awarded for new 0 10 2013 2014 2015 2016 2017 2018 2019A3 contracts Rig Years (L Axis) Average Contract Duration (R Axis, Months) Source: IHS Markit RigPoint as of August 2019 1Total utilization reflects rigs currently under contract and contracted for future work as a percentage of the global jackup fleet; includes benign & harsh-environment rigs; average spot day rates include new mutual contracts signed in a given year, excluding contracts for work in India 9 2Fixtures data includes new mutual contracts only 3Year-to-date 2019 annualized

Valaris Fleet 10

Fleet Overview Diverse Fleet Capable of Meeting a Broad Spectrum of Customers’ Well Program Requirements Drillships Semisubmersibles Jackups 16 Total 12 Total 54 Total – Average age of 6 years – 9 modern assets with sixth – 7 heavy duty ultra-harsh & 7 heavy – 11 assets equipped with dual 2.5 generation drilling equipment duty harsh environment rigs million lbs. hookload derricks and – 3 rigs capable of working in both – 14 heavy duty & 11 standard duty two blowout preventers moored and dynamically- modern benign environment rigs positioned mode – 15 standard duty legacy rigs 11

Highest-Specification Drillships1 Total Utilization Valaris Asset Value2 ($B) 100% 11 12 Valaris All Other 80% 47 of 127 $5.3 4 drillships Seadrill 60% worldwide 12 $3.3 4 Transocean Noble 4 40% Diamond 2013 2014 2015 2016 2017 2018 2019 Gross Asset Replacement Value Value Day Rates for New Contracts Illustrative Rig-Level EBITDA Scenarios3 ($M) (2013 – Current) 100% Day Rate H 90% L $200K M $300K H $500K M 80% L 70% (40) 241 803 Total Total Utilization 70% L M 85% 80 422 1,104 Utilization for highest-specification drillships at time of contract signing 60% Utilization $100 $200 $300 $400 $500 $600 $700 H 95% 161 542 1,305 Day Rates – $K/day Source: IHS Markit RigPoint as of August 2019; Wells Fargo Securities as of August 2019 12 1Drillships delivered in 2013 or later, equipped with dual BOP and 2.5mm lbs. hookload derricks. Includes 7 rigs that are under construction; 2Based on Wells Fargo Securities estimates; 3Assumes average operating expense of $150K/day, unadjusted for changes in utilization

Contract Status & Priorities For Marketed Floaters1 2H19 2020 2021 Priorities VALARIS DS-8 VALARIS DS-9 VALARIS DS-10 VALARIS DS-16 • Increase contracted backlog on active rigs with VALARIS DS-18 near-term availability VALARIS DS-7 Drillships VALARIS DS-12 VALARIS DS-15 VALARIS DS-17 • Warm stack and reduce costs to <$40K/day VALARIS DS-11 until active rigs are contracted and day rates VALARIS DS-6 VALARIS DS-4 are at levels that justify additional supply VALARIS 8505 VALARIS 8503 • Increase contracted backlog on active rigs with VALARIS DPS-1 near-term availability; warm stack and reduce VALARIS 8504 costs to <$30K/day if uncontracted VALARIS MS-1 Semisubmersibles VALARIS 5004 • Divest unless new contract covers capital VALARIS 6002 investment required to keep rigs active and VALARIS 5006 provides adequate return of capital Contracted Options 1 Excludes 2 drillships that are under construction as well as 2 drillships and 4 semisubmersibles that are preservation stacked 13

Heavy Duty Ultra-Harsh & Harsh Environment Jackups1 Total Utilization Valaris Asset Value3 ($B) 100% 13 Valaris 2 33 75 All Other 11 of 583 80% Maersk jackups worldwide $4.0 10 Noble $1.8 3 5 60% COSL Borr 2012 2013 2014 2015 2016 2017 2018 2019 Gross Asset Replacement Value Value Day Rates for New Contracts Illustrative Rig-Level EBITDA Scenarios4 ($M) (2012 – Current) 100% Day Rate H 90% L $100K M $150K H $200K M 80% L 70% - 166 332 Total Total Utilization L 70% M 85% 71 273 475 Utilization for heavy duty ultra-harsh & harsh environment jackups at time of contract signing 60% Utilization $50 $150 $250 $350 $450 H 95% 119 344 569 Day Rates – $K/day Source: IHS Markit RigPoint as of August 2019; Wells Fargo Securities as of August 2019 1Includes jackups with the following rig designs: GustoMSC CJ70, Le Tourneau Super Gorilla Class and KFELS N Class, and other jackup 14 designs classified as harsh environment and North Sea capable < 20 years of age; 2Includes 22 rigs that are under construction; 3Based on Wells Fargo Securities estimates; 4Assumes average operating expense of $70K/day, unadjusted for changes in utilization

Contract Status & Priorities For Heavy Duty Ultra-Harsh & Harsh Environment Jackups 2H19 2020 2021 Priorities VALARIS JU-250 VALARIS JU-247 Harsh - VALARIS JU-290 VALARIS JU-292 VALARIS JU-291 Heavy Duty Ultra Heavy VALARIS JU-249 VALARIS JU-248 • Increase contracted backlog on active rigs with VALARIS JU-120 near-term availability VALARIS JU-123 VALARIS JU-122 VALARIS JU-1001 VALARIS JU-121 Heavy Duty Harsh Heavy VALARIS JU-102 VALARIS JU-101 Contracted Options Leased to ARO Drilling 1 VALARIS JU-100 excluded from slide 14 as the rig is >20 years of age 15

Modern Heavy Duty & Standard Duty Jackups1 Valaris Asset Value2 ($B) Total Utilization 25 100% Valaris 21 80% 174 Borr 95 of 583 jackups 12 $4.8 All Other worldwide Seadrill 60% 12 $2.7 COSL 9 Aban 40% Gross Asset Replacement 2012 2013 2014 2015 2016 2018 2019 2017 Value Value Day Rates for New Contracts Illustrative Rig-Level EBITDA Scenarios3 ($M) (2012 – Current) 100% Day Rate H 90% L $75K M $100K H $150K M 80% L 70% (23) 137 456 Total Total Utilization 70% L Utilization for modern heavy M 85% 80 274 662 duty & standard duty jackups at time of contract signing 60% Utilization $0 $100 $200 $300 H 95% 148 365 798 Day Rates – $K/day Source: IHS Markit RigPoint as of August 2019; Wells Fargo Securities as of August 2019 16 1Benign environment jackups < 20 years of age with 1.5 million lbs. hookload derrick capacity, a minimum of three mud pumps and capable of operating in a minimum water depth of 340 ft. Includes 20 rigs that are under construction; 2Based on Wells Fargo Securities estimates; 3Assumes average operating expense of $55K/day, unadjusted for changes in utilization

Contract Status & Priorities For Marketed Modern Heavy Duty & Standard Duty Jackups1 2H19 2020 2021 Priorities VALARIS JU-106 VALARIS JU-116 VALARIS JU-108 VALARIS JU-109 VALARIS JU-110 • Increase contracted backlog on active rigs VALARIS JU-117 VALARIS JU-115 with near-term availability Heavy Duty Modern Duty Modern Heavy VALARIS JU-107 VALARIS JU-104 VALARIS JU-118 • Warm stack and reduce costs to <$30K/day VALARIS JU-76 if uncontracted VALARIS JU-148 VALARIS JU-147 VALARIS JU-143 • Reactivate preservation stacked capacity if VALARIS JU-146 initial contract covers reactivation cost and VALARIS JU-141 provides adequate return on capital VALARIS JU-140 Standard Standard Modern Duty VALARIS JU-144 VALARIS JU-75 VALARIS JU-145 Contracted Options Leased to ARO Drilling 1 Excludes 5 jackups that are preservation stacked or cold stacked 17

Valaris Value Proposition Context for Illustrative EBITDA Scenarios Floater Average Utilization and Day Rates By Year (2008 – Current) • Average day rates for 100% modern floaters and jackups H 2013 bottomed during 2018 after 90% 2011 2009 reaching recent highs 80% M 2015 between 2012 and 2014 YTD 70% 2019 2017 • Based on historical build 60% Includes new contracts for all benign environment floaters delivered from 2000 onwards costs, we expect that day 50% $100 $200 $300 $400 $500 $600 rates would need to be $K/day higher than the average used Jackup Average Utilization and Day Rates By Year in Scenario H to incentivize (2008 – Current) new rig orders 100% H – Since 2000, the average build 90% 2013 costs for floaters was ~$665 M 2011 80% million, while jackups averaged YTD 2009 2019 2015 ~$200 million; an average day 70% rate of ~$490K for floaters and ~$160K for jackups would be 60% 2017 Includes new contracts for all jackups delivered from 2000 onwards needed to meet a 15% unlevered 50% internal rate of return1 $60 $80 $100 $120 $140 $160 $180 $K/day Source: IHS Markit RigPoint; Valaris analysis for comparable operating geographies 1 Discounted cash-flow analysis assumes 35-year useful life, average opex of $150K/day, $5 million of annual maintenance costs, $10 million of 18 survey costs every five years for floaters; and 30-year useful life, average opex of $50K/day, $2.5 million of annual maintenance costs, $7 million of survey costs every five years for jackups; and 90% operational utilization. Analysis excludes debt service costs, shore-based support costs, taxes, and assumes no residual value at the end of the asset life.

Valaris Value Proposition Illustrative Rig-Level $ Million Annual EBITDA Asset Values2 Scenarios1 Replace- Fleet M H Gross ment Highest Specification Drillships3 (11) $422 $1,305 $3,300 $5,304 Heavy Duty Ultra-Harsh & HE Jackups3 (13) 273 569 1,755 4,002 Modern Heavy & Standard Duty Jackups3 (25) 274 798 2,719 4,768 ARO Drilling Jackups4 (7) 51 94 455 575 Other Drillships5 (5) 153 376 1,298 2,570 Semisubmersibles6 (12) 263 559 868 4,902 Other Jackups7 (16) 159 292 297 2,304 Total $1,595 $3,993 $10,692 $24,425 Source: Wells Fargo Securities as of August 2019; Valaris analysis 1Utilization assumptions: M: 85%, H: 95%; 2Based on Wells Fargo Securities estimates as of August 2019; 3Illustrative annual EBITDA based on assumptions from M and H scenarios in slides 12-14; 4Represents 50% ownership interest from ARO Drilling’s 7 owned rigs; Assumes day rates of M: $100K/day, H: $125K/day and average operating expense of $45K/day, unadjusted for changes in utilization; 5Assumes day rates of M: $275K/day, H: $375K/day and average operating expense of $150K/day, unadjusted for changes in utilization; 6Assumes day rates of M: 19 $200K/day, H: $250K/day and average operating expense of $110K/day, unadjusted for changes in utilization for 12 semisubmersibles; 7Assumes day rates of M: $85K/day, H: $100K/day and average operating expense of $45K/day, unadjusted for changes in utilization

ARO Drilling 20

ARO Drilling Overview 50% 50% Ownership Ownership Valaris operates eight jackups offshore Saudi Arabia outside of ARO ~$450M ~$450M Drilling joint venture Shareholder Shareholder Notes Receivable Notes Receivable Leased Rigs (9) Owned Rigs (7) Newbuild Rigs (20) • Three-year contracts; day rates set • Rigs contracted for three-year • Initial 8-year contracts; day rate by an agreed pricing mechanism terms set by an EBITDA payback • Valaris receives bareboat charter • Renewed and re-priced every mechanism1 fee based on % of rig-level EBITDA three years for at least an • Further 8-year contracts; day rate • ~$210M of bareboat charter aggregate of 15 years set by a market pricing mechanism revenue backlog to Valaris as of and re-priced every three years June 30, 2019 (no associated • Preference given for future operating expense to Valaris) contracts thereafter • Expected to generate $160-180M EBITDA in 2019 • Rigs contribute to ARO Drilling results, of which • 50% attributable to Valaris (not reflected in Valaris Valaris recognizes 50% of net income financials) 1 Down payment on each newbuild rig is no more than 25% before delivery. Illustrative in-service newbuild rig capital cost of $200 million 21 would provide an average day rate of ~$165K/day for the initial eight-year contract, based on cash operating costs of $45K/day + shorebase overhead allocation of $ 7.5 million per year

ARO Drilling Financial Considerations 50% 50% Ownership Ownership ~$450M ~$450M Shareholder Shareholder Notes Receivable Notes Receivable Shareholder Notes Cash & Distributions Future Growth • ~$900M with 10 year maturities • ARO Drilling had more than • 20-rig newbuild program over ten $200M of cash as of March 31, years with first deliveries expected • Issued as consideration for cash 20191 in 2021 and rigs contributed by joint venture partners in 2017 and 2018 • In total, ARO Drilling is expected • Opportunities for external to generate $160-180M EBITDA financing given long-term nature of • Interest rate is LIBOR +2%; during 2019 contracts backed by strong interest can be either paid in cash counterparty or PIK’d on an annual basis at • Excess cash can be distributed to discretion of ARO Drilling Board joint venture partners at the • Expected to be financed by ARO discretion of ARO Drilling Board cash flows or external financing • No third-party debt 1 From Valaris 1Q19 results conference call 22

Financial Management 23

Limited Debt Maturities to 2024 $ millions $1,764 $1,401 $850 $1,000 $850 $695 $621 $914 $400 $300 $201 $123 $114 $112 2019 2020 2021 2022 2023 2024 2025 2026 2027 2040 2042 2044 Unsecured Senior Notes Convertible Notes Note: All amounts as of June 30, 2019 pro forma for tender offers completed in July. Represents principal debt balances outstanding. 24 Borrowing capacity under revolving credit facility is approximately $2.3B through September 2019 and approximately $1.6B from October 2019 through September 2022. On August 1, 2019 the Company repaid the 2019 senior note maturity and drew $125M on the revolver.

While Cash Flow Does Not Cover Costs at This Stage of the Cycle ... Illustrative Annual Illustrative Rig-Level Annual EBITDA Scenarios3 Cash Uses $3,993 million $1,305 • Other non-recurring uses: ‒ Newbuild capex ~$300M $569 Cash Breakeven Scenario Utilization Day Rate ‒ Debt maturities HS Drillships 85% $250,000 HE Jackups 85% $150,000 • Tight management of costs Modern HD & SD Jackups 85% $100,000 ARO Drilling 95% $100,000 is a priority $1,595 million $798 Other Drillships 70% $175,000 Semisubmersibles 70% $150,000 Other Jackups 85% $85,000 $422 $94 ~$950 million $950 million $273 $376 Ops Support Exp. ~$100 million G&A Expense ~$120 million $251 $274 Other1 ~$150 million $495 million $273 $51 Maintenance ~$180 million $558 Capex $153 $274 Interest on $263 ~$400 million Senior Notes2 $64 $292 $160 $159 Category 1 Other Jackups Semis Other Drillships ARO Modern Jackups HE Jackups HS Drillships LTM 4 Cash Breakeven Scenario MM Scenario HH Scenario 1Includes taxes and other items 2Annualized cash interest pro forma for tender offers completed in July 25 3Illustrative annual EBITDA based on M and H scenarios on slide 17 4LTM rig-level EBITDA excludes operations support costs included in contract drilling expense and G&A expense

EBITDA is Cyclical and Currently in Process of Troughing Global Fleet Utilization Valaris Pro Forma EBITDA1 ($B) 100% 90% +70 rigs 34 months 80% +82 rigs 28 months +118 rigs +195 rigs $3.9 +53 rigs $3.7 70% 22 months 40 months $3.5 17 months $3.0 $2.9 $2.0 $1.9 60% $1.7 +103 rigs +81 rigs $1.3 17 months 32 months $0.4 50% 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 1998 1984 1986 1988 1990 1992 1994 1996 2000 2002 2004 2006 2008 2010 2012 2014 2016 2018 Source: IHS Markit RigPoint; Annual and Quarterly Filings 1 EBITDA reflects net income, adjusted for interest, taxes, depreciation and impairment charges from Ensco plc, Rowan Companies plc and 26 Atwood Oceanics, Inc. annual filings; Atwood Oceanics, Inc. 2017 results reflect the 9 months ended June 30, 2017 from their quarterly filing

High-Quality Fleet Provides Significant Asset Coverage to Raise Capital to Cover Interim Funding Gaps • Largest fleet in the offshore drilling $ billions $25.9 sector; majority of rigs are modern, $24.4 high-specification assets $9.3 • Rig fleet provides meaningful asset $9.8 coverage versus total debt even at $0.3 currently depressed levels $0.6 $5.3 $4.8 $10.7 Gross Asset Value Estimates4 $3.7 $2.5 $0.5 Analyst 1 $11.9 $6.4 $4.0 $2.7 Analyst 2 $10.8 Analyst 3 $10.7 $7.4 $1.8 $6.4 $5.3 Analyst 4 $9.7 $3.3 Analyst 5 $9.1 1 2 3 3 Net Debt Construction Cost Replacement Cost Gross Asset Value Highest-Specification Drillships Heavy Duty Ultra-Harsh & Harsh Environment Jackups Modern Heavy Duty & Standard Duty Jackups ARO Drilling - 50% of ARO Owned Assets Other Source: IHS Markit RigPoint, Wells Fargo Securities, Valaris analysis 1 Net debt represents principal balance of $6.7B less $0.4B of cash as of June 30, 2019 pro forma for tender offers completed in July 2019 2 Construction cost per IHS Markit RigPoint 27 3 Replacement cost and gross asset value per Wells Fargo Securities quarterly report dated August 22, 2019 4 Analyst Gross Asset Value Estimates include DNB Markets, Fearnley Securities, Morgan Stanley, SpareBank and Wells Fargo

Unsecured Capital Structure Provides Flexibility to Raise Capital Financial Levers Comparison to Peers3 % of • Liquidity % of Total Debt Unsecured % of – Cash & short-term investments Unsecured ($ billion) Non- Secured 1 Guaranteed – Revolving credit facility Guaranteed • Issuance of securities Transocean $9.8 40% 24% 36% – Valaris is one of two public offshore Seadrill $6.8 - - 100% drillers that have not issued guaranteed or secured financing to date Valaris $6.7 100% - - Noble $3.9 68% 29% 3% • Monetization of assets Unsecured Senior Notes Diamond $2.0 100% - - • Other $6.7 Billion Maersk $1.5 - - 100% – Arbitration tribunal award (SHI); $180 million awarded, plus claims for interest Borr $1.4 25% - 75% and related costs2 – ~$450 million ARO shareholder notes Pacific $1.0 - - 100% 1 Borrowing capacity under revolving credit facility is approximately $2.3B through September 2019 and approximately $1.6B from October 2019 through September 2022 2 There can be no assurance when the Company will be paid all or any portion of the damages awarded or any related interest or costs 28 3 Based on most recent public filings, pro forma for recent transactions. Valaris as of June 30, 2019 pro forma for tender offers completed in July

Integration, Synergies & Operational Highlights 29

Operational Excellence Consistent Operational Results Industry-Leading Customer Satisfaction Fleet-Wide Operational Effectiveness1 99% 99% 99% 99% 98% 98% 2016 2017 2018 Ensco Rowan • Achieved nearly 100% operational • Won 10 of 17 categories in latest survey2 effectiveness for the past three years ‒ Total Satisfaction ‒ Job Quality ‒ Health, Safety & ‒ HPHT Wells Environment • Focus on optimizing customers’ well ‒ Ultra-Deepwater Wells ‒ Performance & Reliability delivery through well planning, drilling ‒ Deepwater Wells performance and performance contracts ‒ Middle East ‒ Shelf Wells ‒ North Sea 1 Average of legacy Ensco “Operational Utilization” and legacy Rowan “Billed Uptime” for 2016, 2017 and 2018 30 2 2018 Oilfield Products & Services Customer Satisfaction Survey conducted by EnergyPoint Research

Innovation & Technology Strategy Drilling Process Efficiency • Continuous Tripping Technology™ is a patented • Focused efforts on system that fully automates the pipe tripping process technology, systems and without stopping to make or break connections, processes to differentiate our enabling 3x faster tripping speeds and delivering assets from the competition expected cost savings along with safer, more reliable through better performance operations and reliability; key areas • Prototype installed on VALARIS JU-123, and include: technology is actively being marketed to customers ‒ Improvements to the drilling process Equipment Maintenance ‒ Equipment reliability • Management systems increase operational uptime ‒ Better productivity from our and decrease lifecycle costs by optimizing asset operations usage and maintenance activities • Currently deploying systems across the fleet that leverage best practices from legacy companies • Our scale provides us with the ability to economically Placing Jackups on Location develop and deploy new technologies across a wide • Proprietary technologies create significant cost asset base and geographic savings for customers by optimizing jackup moves and footprint reducing downtime spent waiting on weather • Technology available on several jackups currently operating 31

Global Reach and Geographic Diversity • Presence in virtually all major offshore regions • Critical mass of highest-specification drillships well positioned to serve major deepwater basins of West Africa, South America and Gulf of Mexico • Versatile semisubmersible fleet capable of meeting a wide range of customer requirements including strong presence offshore Australia • Leading provider of shallow-water jackup services in the Middle East and North Sea Drillships Heavy Duty Ultra-Harsh Environment Jackups Standard Duty Modern Jackups Semisubmersibles Heavy Duty Harsh Environment Jackups Standard Duty Legacy Jackups Heavy Duty Modern Jackups 32

Valaris Rebranding • Establish capabilities as a larger, more global offshore driller ‒ Technologically-advanced, highly capable fleet of deep- and shallow- Strategic water rigs Positioning ‒ Largest global footprint ‒ Focus on operational efficiency and excellence ‒ Decades of expertise and knowledge • Reinforce our role as a partner to customers Customer ‒ Trusted to be there where needed and when needed ‒ Instill confidence in our ability to do the job well, with an emphasis on Alignment integrity and safety ‒ Unrelenting customer-focus • Accelerate cultural alignment Employee ‒ Encourage employee behaviors that are in line with our values, helping us to achieve our purpose Alignment ‒ Create unifying identity so employees associate with the new, combined company instead of legacy companies 33

Merger Integration and Synergies Targeted Synergies Progress to Date • $165 million of run rate annual • More than 50% of integration- expense synergies related activities completed – G&A and other support costs – 65% of planned staffing reductions – Regional office consolidation – Houston and Aberdeen regional – Inventory, logistics and other vendor office and warehouse consolidation synergies – Major ERP conversion • Expect to achieve more than 75% • $80 million of annual run rate of these synergies by the end synergies achieved by the end of of first quarter 2020, with full run second quarter 2019 rate achieved by year-end 2020, creating $1.1 billion of capitalized • Evaluating additional synergy value opportunities that could lead to increase in targeted synergies 34

Appendix 35

Global Rig Fleet 1 Floaters Jackups • ~35 floaters could be Delivered Rigs candidates for retirement based Under Contract 128 338 on age and contract expirations Future Contract 29 39 Idle / Stacked 38 68 • ~150 jackups1 could be retired Marketed Fleet 195 445 as expiring contracts and Non-Marketed 45 76 Total Fleet 240 521 survey costs lead to the removal of older rigs from Marketed Utilization 81% 85% drilling supply Total Utilization 65% 72% Newbuild Rigs • Uncontracted newbuilds Contracted 2 3 expected to be delayed further, Uncontracted 26 57 while several newbuild jackups Total Newbuilds 28 60 in China are unlikely to join the global fleet Source: IHS Markit RigPoint as of August 2019 36 1Includes rigs >30 years of age that are idle without follow-on work or have contracts expiring before year-end 2019 without follow-on work and rigs 15 to 30 years of age that have been idle for more than two years and without follow-on work

Retirements Expected to Lead to Future Supply Contraction Illustrative Floater Supply • Further floater retirements 129 floaters retired since 3Q14 expected to offset newbuild 23 -17 -11 deliveries 240 5 -7 >30yrs idle 233 Other 27 w/o future >30yrs Build in Brazil Newbuilds – Excluding another 27 floaters that Newbuilds contract rolling off 15-30yrs contract by idle for 206 over 2yrs are not currently marketed, YE2019 Non- marketed illustrative marketed supply of 206 compares to contracted floater Current Illustrative Illustrative count of 157 Total Total Marketed Supply Supply Supply • When adjusting for likely Illustrative Jackup Supply retirements and newbuilds, the 19 -96 28 95 jackups retired since 3Q14 jackup count could decline by 521 Other ~100 rigs or nearly 20% Chinese Newbuilds -50 Newbuilds1 >30yrs idle -6 416 10 w/o future 406 – Excluding another 10 jackups that contract >30yrs 15-30yrs Non- rolling off are not currently marketed, idle for marketed contract by over 2yrs YE2019 illustrative marketed supply of 406 compares to contracted jackup Current Illustrative Illustrative Total Total Marketed count of 377 Supply Supply Supply Source: IHS Markit RigPoint as of August 2019 37 1Assumes 13 uncontracted Chinese newbuild jackups do not enter the global supply

EBITDA Reconciliations Twelve Months Ended June 30, 2019 Ensco/ Pro Forma $ Millions Valaris Rowan Valaris Net income (loss) $ (127) $ (288) $ (414) Add (subtract): Income tax expense 111 (46) 65 Interest expense 341 89 429 Other (income) expense (715) (8) (724) Operating loss (391) (253) (644) Add (subtract): Depreciation expense 493 286 779 Loss on impairment 43 - 43 Equity in earnings of ARO (1) (17) (18) (Gain) loss on asset disposals 2 (57) (55) Transaction costs 69 11 81 Recovery of certain legal costs (3) - (3) General & adminstrative expense 105 68 173 Operations support costs 70 69 139 Rig-level EBITDA $ 388 $ 107 $ 495 Source: Annual and Quarterly Filings Note: Ensco/Valaris reflects Ensco plc for the nine months ended March 31, 2019, plus Valaris plc for the three months ended June 30, 2019; Rowan reflects 38 Rowan Companies plc for the nine months ended March 31, 2019

EBITDA Reconciliations Financial Year 2009 Financial Year 2010 Pro Forma Pro Forma $ Millions Atwood Ensco Rowan Valaris $ Millions Atwood Ensco Rowan Valaris Net income (loss) $ 251 $ 785 $ 368 $ 1,403 Net income (loss) $ 257 $ 586 $ 280 $ 1,123 Less: Less: (Income) loss from discontinued operations, net - (36) (39) (75) (Income) loss from discontinued operations, net - (29) (12) (41) Income (loss) from continuing operations 251 749 328 1,328 Income (loss) from continuing operations 257 557 268 1,082 Add (subtract): Add (subtract): Income tax expense 46 179 119 344 Income tax expense 63 97 92 252 Other (income) expense 2 (9) 7 - Other (income) expense 2 (18) 19 3 Operating income (loss) 298 919 454 1,671 Operating income (loss) 322 636 378 1,337 Add (subtract): Add (subtract): Depreciation 35 183 124 342 Depreciation 37 210 138 386 Loss on impairment - - - - Loss on impairment - - - - EBITDA $ 334 $ 1,102 $ 578 $ 2,013 EBITDA $ 359 $ 846 $ 517 $ 1,722 Financial Year 2011 Financial Year 2012 Pro Forma Pro Forma $ Millions Atwood Ensco Rowan Valaris $ Millions Atwood Ensco Rowan Valaris Net income (loss) $ 272 $ 606 $ 737 $ 1,614 Net income (loss) $ 272 $ 1,177 $ 181 $ 1,629 Less: Less: (Income) loss from discontinued operations, net - 2 (601) (599) (Income) loss from discontinued operations, net - 46 23 68 Income (loss) from continuing operations 272 608 136 1,015 Income (loss) from continuing operations 272 1,222 203 1,698 Add (subtract): Add (subtract): Income tax expense 53 115 (6) 163 Income tax expense 41 244 (20) 266 Other (income) expense 4 58 20 81 Other (income) expense 6 99 72 176 Operating income (loss) 329 781 150 1,259 Operating income (loss) 319 1,565 255 2,140 Add (subtract): Add (subtract): Depreciation 44 409 184 636 Depreciation 71 559 248 877 Loss on impairment - - - - Loss on impairment - - 8 8 EBITDA $ 372 $ 1,190 $ 333 $ 1,896 EBITDA $ 390 $ 2,124 $ 511 $ 3,025 Financial Year 2013 Financial Year 2014 Pro Forma Pro Forma $ Millions Atwood Ensco Rowan Valaris $ Millions Atwood Ensco Rowan Valaris Net income (loss) $ 350 $ 1,428 $ 253 $ 2,031 Net income (loss) $ 341 $ (3,889) $ (115) $ (3,663) Less: Less: (Income) loss from discontinued operations, net - 5 - 5 (Income) loss from discontinued operations, net - 1,199 (4) 1,195 Income (loss) from continuing operations 350 1,433 253 2,036 Income (loss) from continuing operations 341 (2,689) (119) (2,467) Add (subtract): Add (subtract): Income tax expense 55 226 9 289 Income tax expense 57 141 (151) 46 Other (income) expense 25 100 70 195 Other (income) expense 42 148 103 292 Operating income (loss) 430 1,759 332 2,520 Operating income (loss) 439 (2,401) (167) (2,129) Add (subtract): Add (subtract): Depreciation 118 612 271 1,000 Depreciation 147 538 323 1,008 Loss on impairment - - 5 5 Loss on impairment - 4,219 574 4,793 EBITDA $ 547 $ 2,371 $ 607 $ 3,525 EBITDA $ 586 $ 2,356 $ 730 $ 3,672 Source: Annual and Quarterly Filings 39 Note: EBITDA reflects net income, adjusted for interest, taxes, depreciation and impairment charges from Ensco plc, Rowan Companies plc and Atwood Oceanics, Inc. annual filings; Atwood Oceanics, Inc. 2017 results reflect the 9 months ended June 30, 2017 from their quarterly filing

EBITDA Reconciliations Financial Year 2015 Financial Year 2016 Pro Forma Pro Forma $ Millions Atwood Ensco Rowan Valaris $ Millions Atwood Ensco Rowan Valaris Net income (loss) $ 433 $ (1,586) $ 93 $ (1,060) Net income (loss) $ 265 $ 897 $ 321 $ 1,483 Less: Less: (Income) loss from discontinued operations, net - 129 - 129 (Income) loss from discontinued operations, net - (8) - (8) Income (loss) from continuing operations 433 (1,457) 93 (931) Income (loss) from continuing operations 265 889 321 1,475 Add (subtract): Add (subtract): Income tax expense 46 (14) 64 97 Income tax expense 48 109 5 161 Other (income) expense 53 228 149 430 Other (income) expense (19) (68) 191 105 Operating income (loss) 531 (1,244) 307 (405) Operating income (loss) 294 929 517 1,740 Add (subtract): Add (subtract): Depreciation 172 573 391 1,136 Depreciation 166 445 403 1,014 Loss on impairment 61 2,746 330 3,137 Loss on impairment 104 - 34 138 EBITDA $ 764 $ 2,075 $ 1,028 $ 3,868 EBITDA $ 564 $ 1,375 $ 954 $ 2,892 Financial Year 2017 Financial Year 2018 Pro Forma Pro Forma $ Millions Atwood Ensco Rowan Valaris $ Millions Atwood Ensco Rowan Valaris Net income (loss) $ (24) $ (304) $ 73 $ (255) Net income (loss) $ - $ (637) $ (347) $ (984) Less: Less: (Income) loss from discontinued operations, net - (1) - (1) (Income) loss from discontinued operations, net - 8 - 8 Income (loss) from continuing operations (24) (305) 73 (256) Income (loss) from continuing operations - (629) (347) (976) Add (subtract): Add (subtract): Income tax expense 7 109 27 142 Income tax expense - 90 (52) 38 Other (income) expense 43 64 139 246 Other (income) expense - 303 111 414 Operating income (loss) 26 (132) 238 132 Operating income (loss) - (236) (288) (523) Add (subtract): Add (subtract): Depreciation 122 445 404 970 Depreciation - 479 389 868 Loss on impairment 59 183 - 242 Loss on impairment - 40 - 40 EBITDA $ 207 $ 496 $ 642 $ 1,344 EBITDA $ - $ 284 $ 101 $ 385 Source: Annual and Quarterly Filings 40 Note: EBITDA reflects net income, adjusted for interest, taxes, depreciation and impairment charges from Ensco plc, Rowan Companies plc and Atwood Oceanics, Inc. annual filings; Atwood Oceanics, Inc. 2017 results reflect the 9 months ended June 30, 2017 from their quarterly filing

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